In-Situ Kerogen Conversion and Oxidant Regeneration

ABSTRACT

Disclosed herein are methods for extracting a kerogen-based product from subsurface shale formations. The methods utilize in-situ reactions of kerogen involving liquid phase chemistry at formation temperatures and pressures. These methods rely on chemically modifying the shale-bound kerogen to render it mobile, using chemical oxidants. In the methods disclosed herein an oxidant is provided to the subsurface shale formation comprising kerogen in an inorganic matrix, the oxidant converting the kerogen to form organic acids, and forming a mobile kerogen-based product. The spent oxidant is regenerated in-situ to restore at least some of the original oxidation activity. At least a portion of the mobile kerogen-based product is recovered. The kerogen-derived product can be upgraded to provide commercial products.

RELATED APPLICATION

The subject application is related to U.S. Provisional Application Ser.No. 61/426,340, filed Dec. 22, 2010. This application is also related toU.S. application Ser. No. ______ (attorney docket number70205.0216USU1), entitled “In-Situ Kerogen Conversion and Recovery”filed Dec. 22, 2011; U.S. application Ser. No. ______ (attorney docketnumber 70205.0216USU2), entitled “In-Situ Kerogen Conversion and ProductIsolation” filed Dec. 22, 2011; U.S. application Ser. No. ______(attorney docket number 70205.0216USU3), entitled “In-Situ KerogenConversion and Upgrading” filed Dec. 22, 2011; U.S. application Ser. No.______ (attorney docket number 70205.0216USU4), entitled “In-SituKerogen Conversion and Recycling” filed Dec. 22, 2011; and U.S.application Ser. No. ______ (attorney docket number 70205.0232US01)entitled “Preconditioning a Subsurface Shale Formation by RemovingExtractible Organics” filed Dec. 22, 2011. The contents of all of theserelated applications are incorporated herein by reference in theirentirety.

BACKGROUND

If proponents of Hubbert peak theory are correct, world oil productionwill soon peak, if it has not done so already. Regardless, world energyconsumption continues to rise at a rate that outpaces new oildiscoveries. As a result, alternative sources of energy must bedeveloped, as well as new technologies for maximizing the production andefficient consumption of oil. See T. Mast, Over a Barrel: A Simple Guideto the Oil Shortage, Greenleaf Book Group, Austin, Tex., 2005.

A particularly attractive alternative source of energy is oil shale, theattractiveness stemming primarily from the fact that oil can be“extracted” from the shale and subsequently refined in a manner muchlike that of crude oil. Technologies involving the extraction, however,must be further developed before oil shale becomes a commercially-viablesource of energy. See J. T. Bartis et al, Oil Shale Development in theUnited States: Prospects and Policy Issues, RAND Corporation, Arlington,Va., 2005.

The largest known deposits of oil shale are found in the Green RiverFormation, which covers portions of Colorado, Utah, and Wyoming.Estimates on the amount of recoverable oil from the Green RiverFormation deposits are as high as 1.1 trillion barrels of oil—almostfour times the proven oil reserves of Saudi Arabia. At current U.S.consumption levels (^(˜)20 million barrels per day), these shaledeposits could sustain the U.S. for another 140 years (Bartis et al.) Atthe very least, such shale resources could moderate the price of oil andreduce U.S. dependence on foreign oil.

Oil shale typically consists of an inorganic component (primarilycarbonaceous material, i.e., a carbonate), an organic component(kerogen) that can only be mobilized by breaking the chemical bonds inthe kerogen, and frequently a second organic component (bitumen).Thermal treatment can be employed to break (i.e., “crack”) the kerogeninto hydrocarbon chains or fragments, which are gas or liquids underretort conditions, and facilitate separation from the inorganicmaterial. This thermal treatment of the kerogen is also known as“thermal upgrading” or “retorting,” and can be done at either thesurface or in situ, where in the latter case, the fluids so formed aresubsequently transported to the surface.

In some applications of surface retorting, the oil shale is first minedor excavated, and once at the surface, the oil shale is crushed and thenheated (retorted) to complete the process of transforming the oil shaleto a crude oil—sometimes referred to as “shale oil.” See, e.g., Shumanet al., U.S. Pat. No. 3,489,672. The crude oil is then shipped off to arefinery where it typically requires additional processing steps (beyondthat of traditional crude oil) prior to making finished products such asgasoline, lubricant, etc. Note that various chemical upgradingtreatments can also be performed on the shale prior to the retorting,See, e.g., So et al., U.S. Pat. No. 5,091,076.

A method for in situ retorting of carbonaceous deposits such as oilshale has been described in Kvapil et al., U.S. Pat. No. 4,162,808. Inthis method, shale is retorted in a series of rubblized in situ retortsusing combustion (in air) of carbonaceous material as a source of heat.

The Shell Oil Company has been developing new methods that useelectrical heating for the in situ upgrading of subsurface hydrocarbons,primarily in subsurface formations located approximately 200 miles (320km) west of Denver, Colo. See, e.g., Vinegar et al., U.S. Pat. No.7,121,342; and Berchenko et al., U.S. Pat. No. 6,991,032. In suchmethods, a heating element is lowered into a well and allowed to heatthe kerogen over a period of approximately four years, slowly converting(upgrading) it into oils and gases, which are then pumped to thesurface. To obtain even heating, 15 to 25 heating holes could be drilledper acre. Additionally, a ground-freezing technology to establish anunderground barrier around the perimeter of the extraction zone is alsoenvisioned to prevent groundwater from entering and the retortingproducts from leaving. While the establishment of “freeze walls” is anaccepted practice in civil engineering, its application to oil shalerecovery still has unknown environmental impacts. Additionally, theShell approach is recognized as an energy intensive process and requiresa long timeframe to establish production from the oil shale.

In view of the aforementioned limitations of the above methods, simplerand more cost-effective methods of extracting the kerogen from the shalewould be extremely useful.

SUMMARY OF THE INVENTION

The present invention is directed to processes for producing mobileproducts from the organic matter that occurs in subsurface oil shale.Among other factors, these processes are based on the discovery thatkerogen in oil shale can be made to react at temperatures belowpyrolysis temperatures to produce mobile reaction products that can beremoved from the subsurface shale formation, recovered in surfacefacilities and upgraded to produce useful products, refinery feedstocks,fuel and lubricant blendstocks, reaction intermediates and the like. Thepresently disclosed processes are more environmentally benign, moreeconomical, and more efficient in producing commercial products.

Disclosed herein is a process for extracting a kerogen-based productfrom a subsurface shale formation comprising kerogen using a chemicaloxidation. The multi-step extraction process, including the oxidationstep, is generally conducted at temperatures near the natural reservoirtemperature. In embodiments, the oxidation step is conducted at atemperature in the range of from 0° C. to 200° C.

As disclosed herein, the process includes an oxidation step, using achemical oxidation process, and a regeneration step, which regeneratesthe oxidant and restores at least a portion of its activity as anoxidizing agent. Accordingly, disclosed herein is a process forextracting a kerogen-based product from a subsurface shale formationcomprising subsurface shale, including providing a first oxidant tokerogen in subsurface shale; contacting the kerogen in the subsurfaceshale with the first oxidant at a temperature in the range from 0° C.and 200° C. to form organic acids; mobilizing at least a portion of theorganic acids from the subsurface shale to produce a mobilekerogen-based product; and regenerating the first oxidant in thesubsurface shale.

In the process, kerogen conversion reactions, the oxidant regenerationreactions and the product extraction are conducted at the same, or atdifferent, pH ranges. In embodiments, at least one of the conversion,regeneration, and extraction steps are conducted with a formation fluidthat is present in the subsurface shale formation. In embodiments, theprocess includes providing the first oxidant to the kerogen at a pH inthe range from 7 to 9. In embodiments, a second oxidant is provided tothe formation fluid, for purposes of regenerating the first oxidant, theformation fluid having a pH in the range from 6 to 8. In embodiments,organic acids are mobilized in the formation fluid as a result of theconversion process at a pH in the range from 12 to 14, to form themobile kerogen-based product.

In one embodiment, the process for extracting a kerogen-based productfrom a subsurface shale formation comprising subsurface shale involves acyclic process, including the steps of providing a first oxidant tokerogen in subsurface shale; contacting the kerogen in the subsurfaceshale with the first oxidant to form organic acids; and regenerating thefirst oxidant in the subsurface shale, in a multiplicity of processingcycles. In one such embodiments, at least a portion of the organic acidsfrom the subsurface shale formation are recovered to provide a mobilekerogen-based product, prior to the step of regenerating the firstoxidant. In another of such embodiments, at least a portion of theorganic acids from the subsurface shale formation are recovered toprovide a mobile kerogen-based product, subsequent to the multiplicityof regeneration cycles.

In a further embodiment, the process includes the steps of: providing afirst oxidant to kerogen in subsurface shale; contacting the kerogen inthe subsurface shale with the first oxidant at a temperature in therange from 0° C. and 200° C. to form organic acids; mobilizing at leasta portion of the organic acids from the subsurface shale to produce amobile kerogen-based product; recovering the mobile kerogen-basedproduct comprising the organic acids; and regenerating the first oxidantin the subsurface shale.

In a further embodiment, the process includes the steps of: providing afirst oxidant to kerogen in subsurface shale; contacting the kerogen inthe subsurface shale with the first oxidant at a temperature in therange from 0° C. and 200° C. to form organic acids; mobilizing at leasta portion of the organic acids from the subsurface shale to produce amobile kerogen-based product; regenerating the first oxidant in thesubsurface shale; and recovering the mobile kerogen-based productcomprising the organic acids.

In a further embodiment, the process includes the steps of: providing afirst oxidant to kerogen in subsurface shale; contacting the kerogen inthe subsurface shale with the first oxidant at a temperature in therange from 0° C. and 200° C. to form organic acids; providing a secondoxidant to the kerogen in the subsurface shale to regenerate the firstoxidant in a regeneration step; contacting the kerogen in the subsurfaceshale with the regenerated first oxidant for a period of at least 4hours to form organic acids; repeating the regeneration step ofproviding the second oxidant to the kerogen in the subsurface shale toregenerate the first oxidant; and recovering a mobile kerogen-basedproduct comprising the organic acids.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram illustrating an exemplary sequence of stepsinvolving providing a reactive fluid comprising an oxidant to asubsurface shale formation that contains kerogen, regenerating theoxidant, recovering a mobile kerogen-based product from the formationand isolating organic acid products from the mobile kerogen-basedproduct.

FIG. 2 is a block diagram illustrating the added step of passing anorganic extractant to the mobile kerogen-based product for extracting atleast a portion of the organic acids contained in the mobilekerogen-based product.

FIG. 3 is a block diagram illustrating an exemplary sequence of stepsinvolving providing a reactive fluid to a subsurface shale formationthat contains kerogen, providing an extractive fluid for mobilizingorganic acids that are generated from kerogen reactions, recovering amobile kerogen-based product from the formation and isolating organicacid products from the mobile kerogen-based product.

FIG. 4 illustrates carbon chain-size distribution of low molecularweight acids in kerogen permanganate oxidation products determined bygas chromatography/mass spectrometry.

FIG. 5 illustrates carbon chain-size distribution of hydrocarbonproducts formed by pyrolysis of high molecular weight organic acids inkerogen permanganate oxidation products determined by pyrolysis gaschromatography/mass spectrometry.

DETAILED DESCRIPTION OF THE INVENTION Introduction

The present invention is directed to methods of extracting akerogen-based product from subsurface shale formation comprising kerogenin an inorganic matrix. The methods rely on chemically modifying theshale-bound kerogen to render it mobile using an oxidant that isprovided to the kerogen in the subsurface shale in a liquid medium. Theoxidant converts the kerogen to a mobile kerogen-based product attemperatures below that at which the kerogen thermally decomposes bypyrolysis or thermal cracking. The oxidant (i.e. first oxidant) ismaintained in the subsurface shale formation for sufficient time tosignificantly reduce the oxidation activity of the oxidant. A secondoxidant is then provided to the subsurface shale to regenerate the firstoxidant and to restore at least some of the oxidation activity of thefirst oxidant. The present invention is also directed to systems forimplementing such methods.

The process is for the conversion of carbonaceous deposits into mobileproducts, which may be recovered for use in the generation of energyand/or in the production of fuels, lubricants, solvents and/orpetrochemicals that are generally formed during petroleum processing andrefining. Any carbonaceous deposit may be beneficially treated by theprocess. Exemplary deposits include oil shale, coal, tar sands, heavyoil and the like. In the following description of the process, specificattention is paid to converting the hydrocarbonaceous material thatoccurs in what is commonly termed “oil shale”, with the understandingthat application of the process in its general form is not so limited.

DEFINITIONS

In accordance with this detailed description, the followingabbreviations and definitions apply. It must be noted that as usedherein, the singular forms “a”, “an”, and “the” include plural referentsunless the context clearly dictates otherwise. Thus, for example,reference to an “oxidant” includes a plurality of such.

As used herein, a range encompasses all values within the limits of thestated range, including the end members of the range. In an illustrativeexample, “having a pH in a range from 8 to 12” includes all integer andfractional values from 8 and 12, including a pH of 8 or a pH of 12.

As used herein, the terms “hydrocarbon” or “hydrocarbonaceous” or“petroleum” are used interchangeably to refer to material originatingfrom oil shale, coal, tar sands, crude oil, natural gas or biologicalprocesses. Carbon and hydrogen are major components of hydrocarbons;minor components, such as oxygen, sulfur and nitrogen may also occur insome hydrocarbons. The hydrocarbon fraction includes both aliphatic andaromatic components. The aliphatic component can further be divided intoacyclic alkanes, referred to as paraffins, and cycloalkanes, referred toas naphthenes. A paraffin refers to a non-cyclic, linear (normalparaffin) or branched (isoparaffin) saturated hydrocarbon. For example,a C₈ paraffin is a non-cyclic, linear or branched hydrocarbon having 8carbon atoms per molecule. Normal octane, methylheptane, dimethylhexane,and trimethylpentane are examples of C₈ paraffins. A paraffin-rich feedcomprises at least 10 wt %, at least 20 wt % or even at least 30 wt %paraffins. For example, a C₈ rich paraffinic feedstock contains at least10 wt. % C₈ hydrocarbons.

As disclosed herein, boiling point temperatures are based on the ASTMD-2887 standard test method for boiling range distribution of petroleumfractions by gas chromatography, unless otherwise indicated. Themid-boiling point is defined as the 50% by volume boiling temperature,based on an ASTM D-2887 simulated distillation.

As disclosed herein, carbon number values (i.e., C₅, C₆, C₈, C₉ and thelike) generally refers to a number of carbon atoms within a molecule.Carbon number ranges as disclosed herein (e.g., C₈ to C₁₂) refer tomolecules having a carbon number within the indicated range (e.g.,between 8 carbon and 12 carbon atoms), including the end members of therange. Likewise, an open ended carbon number range (e.g., C₃₅+) refersto molecules having a carbon number within the indicated range (e.g., 35or more carbon atoms), including the end member of the range. Asdescribed herein, carbon number distributions are determined by trueboiling point distribution and gas liquid chromatography.

Unless otherwise specified, feed rate to a catalytic reaction zone isreported as the volume of feed per volume of catalyst per hour. Ineffect, the feed rate as disclosed herein, referred to as liquid hourlyspace velocity (LHSV), is reported in reciprocal hours (i.e., hr⁻¹).

As used herein, the value for octane refers to the research octanenumber (RON), as determined by ASTM D2699.

The term “surface facility” as used herein is any structure, device,means, service, resource or feature that occurs, exists, takes place oris supported on the surface of the earth. The kerogen products that aregenerated in the process disclosed herein are recovered in surfacefacilities and upgraded or transported for upgrading.

“Shale,” as defined herein, generally refers to “oil shale” and is ageneral term applied to a group of rocks rich enough in organic material(called kerogen) to yield petroleum upon pyrolysis and distillation.Such shale is generally subsurface and comprises an inorganic (usuallycarbonate) component or matrix in addition to the kerogen component.

A “subsurface shale formation,” as defined herein, is an undergroundgeological formation comprising (oil) shale. The subsurface shaleformation comprises kerogen in an inorganic matrix.

A “low-permeability hydrocarbon-bearing formation,” as defined herein,refers to formations having a permeability of less than about 10millidarcies, wherein the formations comprise hydrocarbonaceousmaterial. Examples of such formations include, but are not limited to,diatomite, coal, tight shales, tight sandstones, tight carbonates, andthe like.

“Kerogen,” as defined herein and as mentioned above, is an organiccomponent of shale. On a molecular level, kerogen comprises very highmolecular weight molecules that are generally insoluble by virtue oftheir high molecular weight and likely bonding to the inorganiccomponent or matrix of the shale. In a geologic sense, kerogen is aprecursor to crude oil. Kerogen is typically identified as being one offive types: Type I, Type II, Type II-sulfur, Type III, or Type IV, basedon its C:H:O ratio and sulfur content, the various types generally beingderived from different sources of ancient biological matter.

“Kerogen-based,” and “kerogen-derived are terms used herein to denote amolecular product or intermediate derived from kerogen, such derivationrequiring a chemical modification of the kerogen, and the term beingexclusive of derivations carried out over geologic timescales.

“Extractible organics” are organic components of the subsurface shaleformation that are at least partially soluble in an organic solvent. Incontrast, the kerogen is not soluble in organic solvent. This organiccomponent that is at least partially soluble is referred to herein as“extractible organics”. This extractible organic component includes whatis commonly referred to as “bitumen”. The extractable organic componentis a solid or semi-solid material that is soluble or at least partiallysoluble in an organic solvent. As such, the extractable organiccomponent can be removed by extraction using an organic solvent.Extraction of the extractable organic component makes the kerogen moreaccessible. In the present methods, extraction of the extractableorganic component makes the kerogen more accessible to oxidants forreaction to create mobile kerogen-based product. Extraction of theextractable organic component is disclosed in U.S. application Ser. No.______ (Docket No. 70205.0232US01), “Preconditioning a Subsurface ShaleFormation by Removing Extractable Organics”, filed Dec. 22, 2011, thecontents of which are incorporated herein by reference in theirentirety.

“Organic acid” is a term used herein to denote a molecular entitycontaining at least one carboxylic acid functional group, either in thenon-ionized form (e.g., —COOH), in the ionized form (e.g., —COO—), orsalts thereof. The term “organic acid” is meant to encompass a highmolecular weight kerogen fragment (e.g., a molecular mass of up to12,000 to 15,000 daltons and higher) comprising at least one carboxylicacid functional group. The term “organic acid” is further meant toencompass a low molecular weight acid, including a monoacid such asacetic acid and a diacid such as oxalic acid. As used herein, the term“monoacid” is used to denote having one carboxylic acid functional groupper molecule. Likewise, the term “diacid” denotes two, and “triacid”denotes three carboxylic acid functional groups per molecule.

The term “reactive fluid,” as used herein, refers to fluid comprising anoxidant that is passed to the kerogen in the subsurface shale formation.

The term “extractive fluid,” as used herein, refers to a fluid that isprepared with additives for mobilizing the organic acid reactionproducts in the subsurface shale.

The term “aqueous fluid” as used herein refers to any water containingfluid, including pure water, such as, municipal water; surface water,including from a lake, sea, ocean, river, and/or stream; formationwater; water associated with industrial activity; or mixtures thereof.

The term “formation water” as used herein refers to the water or aqueousfluid that is naturally occurring in a geological formation, such as thesubsurface shale formation, or in a subsurface aquifer. The amount (orpresence) of formation water in the formation, and the amount (orpresence) of formation water in contact with the kerogen in theformation, depends on a number of factors, including the depth of thesubsurface shale formation or the kerogen deposit located therein. Insome cases, formation water is present in the formation prior to thestart of the process for extracting a kerogen-based product from asubsurface shale formation. The naturally occurring formation water maycontain dissolved alkali materials from naturally occurring deposits inthe environment of the subsurface shale.

The term “formation fluid” as used herein, is the fluid in contact withthe kerogen in the subsurface shale formation. Formation fluid mayinclude the formation water that occurs naturally at, or in theenvironment of, the subsurface shale. Formation fluid may also include,for example, a fluid (or fluids) that is supplied to the kerogen fromthe surface. Formation fluid may also include, for example, oxidants, orsurfactants, or alkali materials, or mixtures thereof that are suppliedfrom the surface. Formation fluid may also include reaction productsfrom chemical reactions and/or physical absorption processes of thekerogen (and/or bitumen) in the subsurface shale formation.

The term “spent formation fluid,” as used herein, refers to theoxidation activity of the formation fluid, and by extension theconcentration of oxidant in the formation fluid. A spent formation fluidhas a reduced amount of oxidant, and therefore a reduced oxidationactivity toward the conversion of kerogen or products from kerogenconversion. Unless otherwise indicated, a spent formation fluid is onewhich produces an insignificant amount of reaction products at thetemperature of the fluid over the time in which the fluid is withdrawnas a mobile kerogen-based product from the formation.

The terms “natural” or “naturally occurring” refer to conditionsexisting before, or without, human intervention. Thus, a “naturalformation temperature,” as used herein, refers to the temperature of thesubsurface shale formation, prior to or in the absence of humanintervention with or in the formation. In a specific example, anaturally occurring aqueous fluid may originate from a subterraneanaquifer or from a surface body of water such as a river or stream orfrom a pond or lake that has not been modified by man. In anotherspecific example, a “naturally occurring” aqueous basic solution refersto a solution present in the formation prior to, or in the absence of,human intervention in the formation.

A “surfactant” as used herein refers to any substance that reducessurface tension of a liquid, or reduces interfacial tension between twoliquids, or between a liquid and a solid, or facilitates the dispersionof an organic material into an aqueous solution.

The term “basic solution,” as used herein, refers to an aqueous solutionhaving a pH of greater than 7.

The term “acidic solution,” as used herein, refers to an aqueoussolution having a pH of less than 7.

A “dense phase fluid,” as defined herein, is a non-gaseous fluid. Suchdense phase fluids include liquids, supercritical fluids (SCFs), andfluids at supercritical conditions. The dense phase fluid can be anysuch fluid that suitably provides for increased accessibility of thekerogen to a fluid—typically due to fracturing and/or rubblizing of theshale in which the kerogen resides.

A “supercritical fluid,” as used herein, is any substance at atemperature and pressure above its thermodynamic critical point.Supercritical fluids can be regarded as “hybrid solvents” withproperties between those of gases and liquids, i.e., a solvent with alow viscosity, high diffusion rates and no surface tension. Commonsupercritical fluids include supercritical carbon dioxide (CO₂) andsupercritical water. For example, the critical temperature of CO₂ is31.1° C., and the critical pressure of CO₂ is 72.9 atm (7.39 MPa).

The term “mechanical stress,” as used herein, refers to structuralstresses within the shale formation that result from pressure variationswithin the formation. Such stress can lead to fracturing and/orrubblization of the shale formation.

The term “thermal stress,” as used herein, refers to structural stresseswithin the shale formation that result from thermal variations. Suchthermal stresses can induce internal mechanical stresses as a result ofdifferences in thermal coefficients of expansion among the variouscomponents of the shale formation. Like mechanical stress mentionedabove, thermal stress can also lead to fracturing and/or rubblization ofthe shale formation.

The term “fracturing,” as used herein, refers to the structuraldegradation of a subsurface shale formation as a result of appliedthermal and/or mechanical stress. Such structural degradation generallyenhances the permeability of the shale to fluids and increases theaccessibility of the kerogen component to such fluids. The term“rubblization,” as used herein, is a more extensive fracturing processyielding fracture planes in multiple directions that generate shalederived “rubble.”

The term “cracking,” as mentioned in the background section and as usedherein, refers to the breaking of carbon-carbon bonds in the kerogen soas to yield species of lower molecular weight. “Retorting,” providesthermal cracking of the kerogen. “Upgrading,” provides cracking of thekerogen, but can involve a thermal or chemical upgrading agent.Accordingly, the term “thermal upgrading” is synonymous with the term“retorting.”

Hydrocracking is a chemical reaction of liquid feed materials, includinghydrocarbons, petroleum and other biologically derived material, in thepresence of hydrogen and one or more catalysts, resulting in productmolecules having reduced molecular weight relative to that of the liquidfeed materials. Additional reactions, including olefin and aromaticsaturation and heteroatom (including oxygen, nitrogen, sulfur andhalogen) removal may also occur during hydrocracking.

Pyrolysis temperature, as used herein, is the temperature at which thekerogen thermally decomposes without the intervention of a catalytic orchemical agent.

The term “in situ,” as used herein refers to the environment of thesubsurface shale formation.

The term “commercial petroleum-based products,” as used herein, refersto commercial products that include, but are not limited to, gasoline,aviation fuel, diesel, lubricants, petrochemicals, and the like. Suchproducts can also include common chemical intermediates and/or blendingfeedstocks.

“Optional” or “optionally” means that the subsequently described eventor circumstance may, but need not, occur, and that the descriptionincludes instances where the event or circumstance occurs and instancesin which it does not.

Method Overview

The present invention is generally directed to methods for extracting akerogen-based product from a subsurface shale formation comprisingsubsurface shale. The methods include the steps of: providing a firstoxidant to kerogen in subsurface shale; contacting the kerogen in thesubsurface shale with the first oxidant at a temperature in the rangefrom 0° C. and 200° C. to form organic acids; mobilizing at least aportion of the organic acids from the subsurface shale to produce amobile kerogen-based product; and regenerating the first oxidant in thesubsurface shale.

The step of contacting the kerogen with an oxidant generally involves anin situ chemical modification of the kerogen (e.g., cracking) and/orsurrounding shale so as to render the modified kerogen component mobile.Such chemical modification generally involves the making and/or breakingof chemical bonds. In one embodiment, the chemical modification involvesthe formation of reaction products that contain organic acid and/ororganic acid functional groups. At least a portion of these reactionproducts may be mobilized using an alkaline aqueous solution. The stepof transporting the mobile kerogen-based product out of the subsurfaceshale formation can generally be described as a means of flowing themobile kerogen-based product out of the subsurface formation, where sucha means can be active (e.g., pumping) and/or passive.

In an embodiment, the step of isolating the organic acids from themobile kerogen-based product involves reducing the relative solubilityof the organic acids in the mobile kerogen-based product. One exemplarymethod involves converting an ionized form of the acid, e.g., a salt ofthe acid such as a sodium salt, to the corresponding protonated (e.g.,non-ionized) form of the acid. In another embodiment, reducing therelative solubility involves contacting the mobile kerogen-based productwith a hydrocarbonaceous extractant for extracting at least some of theorganic acids from the mobile kerogen-based product to thehydrocarbonaceous extractant. In another embodiment, reducing therelative solubility involves converting the acid to a correspondingester. In an embodiments, the step of isolating the soluble organicacids involves separating the acids from a carrier fluid by physicalmeans, such as, for example, liquid-liquid separation, distillation,membrane separation, froth flotation, phase separation, electrostaticseparation, coalescence, biological processes, thermal separationprocesses, and steam distillation.

In one embodiment, the above-described method may involve one or moreadditional steps which serve to sample and subsequently analyze theshale prior to, or in the alternative during, or in the alternativeafter, performing the step of increasing the accessibility of thekerogen. Such sampling and analysis can have a direct bearing on thetechniques employed in the subsequent steps.

In one embodiment, the extracted kerogen-based product is upgraded(thermally and/or chemically) in a surface facility. Such surfaceupgrading can be intermediate to subsequent refining.

In an illustrative embodiment, a reactive fluid containing at least onereactive component and having a pH of at least 7 is provided to thekerogen in the subsurface shale. The reactive component facilitatescracking reactions in the kerogen, producing mobile organic acidreaction products. The mobile reaction products are absorbed into anaqueous fluid to form a mobile kerogen-based product; the reactionproduct enriched aqueous fluid is then removed to surface facilities forprocessing. A reactive fluid may further be provided to the subsurfaceshale for dissolving or otherwise absorbing mobile reaction products forremoval to surface facilities for processing. In another illustrativeembodiment, the reactive fluid containing at least one reactivecomponent, and having a pH of less than or equal to 7 is provided to thekerogen in the subsurface shale.

The subsurface shale formation comprises an organic component, at leasta portion of which is the kerogen as defined herein. The subsurfaceshale formation further comprises an inorganic component in addition tothe kerogen.

The subsurface shale formation is accessed from the surface through atleast one well. In general, the well will be cased, at least for aportion of its distance. Specifications for drilling access wells into asubsurface shale formation are known. In most applications of theinvention, multiple wells will be provided into the subsurface shaleformation, the well pattern based on recognized principles for thisapplication. In one embodiment, a portion of the wells are employed asinjection wells for passing fluids from the surface to the formation,and a portion of the wells are employed as production wells forwithdrawing fluids from the formation to the surface. Each of themultiple wells may be used successively as an injection well and aproduction well, depending on the needs of the process. In analternative, each well may be prepared and managed optimally as eitheran injection well or a production well. Specifications of each well forpreparing and using the well as an injection well and/or a productionwell can readily be developed by one of skill in the art.

Conversion Process

The conversion process is a chemical conversion process, with reagentsbeing provided to the kerogen to facilitate the fracture of chemicalbonds in the kerogen and between the kerogen and the inorganic matrix inwhich the kerogen naturally occurs. While the reagents that are providedto convert the shale may be provided as solids, liquids or gases, it hasbeen found that the conversion reactions are facilitated by theintroduction of liquid phase materials, or alternatively by using liquidphase materials that are naturally present in the shale formation, forconverting the kerogen. Use of liquid phase oxidants during kerogencracking conversion may advantageously be conducted at liquid phasetemperatures, including temperatures in the range from 0° C. to 200° C.The kerogen cracking conversion may advantageously be conducted atformation pressure, or at a pressure sufficiently above formationpressure to permit provision of liquid phase reactants to the kerogen inthe oil shale formation.

Oxidant

In one embodiment, the process includes providing an oxidant to kerogenin subsurface shale. Depending on the oxidant, it may be provided insolid, liquid or gaseous form. In liquid form, the oxidant may beprovided in acidic, neutral, or alkaline conditions; the choice of pHdepends at least in part on the type of oxidant used. Some oxidants arebetter suited for acidic conditions. For oxidants of this type, theoxidant is provided to the kerogen at a pH in a range from 1.5 to 6.5.Maintaining the pH in this range will generally require the addition ofan acidic material to the kerogen. Examples include mineral acids suchas hydrochloric acid, sulfuric acid, nitric acid, phosphoric acid andcombinations thereof, or organic acids such as one or more of thecarboxylic acids having from 2 to 15 carbon atoms, or mixture thereofmay be used. With the carboxylic acids, monoacids, diacids, or triacidsmay be used. In one embodiment, the pH is maintained in a range from 1.5to 6.5 by provision of CO₂ to the kerogen, alone or in combination withother acids.

Some oxidants are better suited for conditions at neutral pH. Supplyingoxidants of this type generally involves supplying the oxidants incombination with a buffered solution, to maintain the pH in the neutralrange while contacting the mineral matter within the subsurface shale.

In one embodiment, the oxidant is provided to the kerogen at a pH in arange from 7 to 14, with an embodiment in the range from 7 to 9.Maintaining the pH in the desired alkaline range will be facilitated insome situations by the carbonate and bicarbonate materials that arenatural to the subsurface shale formation. Otherwise, the pH in therange from 7 to 14, or in the range from 7 to 9, may be maintained bysupply of an alkaline material, such as a carbonate, a bicarbonate, anoxide, a hydroxide, or combinations thereof. In one embodiment, the pHis maintained in a range from 7 to 9 by provision of CO₂ to the kerogen.

Carrier Fluid

In one embodiment, the oxidant is provided to the kerogen in combinationwith a carrier fluid, the combination being prepared in surfacefacilities and passed to the subsurface shale through an injection well.Exemplary carrier fluids include an aqueous fluid, an ethanol fluid orcombinations thereof. An ethanol fluid contains ethanol, and typicallyat least 30 wt. % ethanol, such as from 30 wt. % to 100 wt. % ethanol.The ethanol fluid may also contain water. Likewise, the aqueous fluidmay contain ethanol. In one embodiment, the carrier fluid encompasses aconcentration range from 100 wt. % water to 100 wt. % ethanol, or anycombination between.

The carrier fluid generally contains sufficient oxidant to facilitatethe production of organic acids from the kerogen in a desired timeframe. Higher concentrations of the oxidant generally results in fasterreaction rates. In one embodiment, the carrier fluid contains from 0.1wt. % to 40 wt. % of the oxidant; in another embodiments from 0.1 wt. %to 25 wt. %; in another embodiment from 1 wt. % to 15 wt. %.

The carrier fluid is prepared at a pH that is suited for the particularoxidant used. In one embodiment, the carrier fluid has a pH in the rangefrom 7 to 14; in another embodiment in the range from 7 to 9; in anotherembodiment in the range from 1.5 to 6.5. Alkaline materials, inorganicacids, organic acids and CO₂ are suitable reagents for the preparationof the carrier fluid at different pH levels.

In one embodiment, the carrier fluid comprises an organic solvent.Illustrative organic solvents that are suitable include refinery streamsboiling in the range from 100° C. to 500° C.; C₄ to C₂₁ hydrocarbons,including naphtha, diesel fuel, and gas oils; alcohols, includingmethanol, ethanol, propanol, butanol; aromatics, including benzene,toluene, the xylenes and alkyl substituted variations thereof; ethers;ketones; esters; tetralin; n-methyl-2-pyrrolidone; tetrahydrofuran; and2-methyl-tetrahydrofuran. In one embodiment, the formation fluidincludes a mixture of an aqueous solvent and an organic solvent, in anyproportion.

Permanganate Oxidant

In one embodiment, the process includes contacting the kerogen in thesubsurface shale with a permanganate oxidant to form organic acids. Thepermanganate may be supplied to the kerogen from surface facilities,either in solid form or as a solution. When supplied in aqueous orethanol solution, sufficient permanganate is provided to react withkerogen at a temperature in the range of 0° C. to 200° C. to formorganic acids. The permanganate solution may contain up to thesolubility limit of the permanganate at formation temperatures. In oneembodiment, the permanganate solution contains in the range from 0.1 wt.% to 40 wt. % permanganate, or in the range from 0.1 wt. % to 25 wt. %permanganate, or in the range from 1.0 wt. % to 15 wt. % permanganate,expressed in terms of the weight of anhydrous permanganate saltdissolved in a given weight of solution. With ethanol solutions, theethanol may be the only solvent, or it may be used as a co-solvent inthe solution. The permanganate may be any solublepermanganate-containing material. Ammonium permanganate, NH₄MnO₄;calcium permanganate, Ca(MnO₄)₂; potassium permanganate, KMnO₄; andsodium permanganate, NaMnO₄ are suitable permanganates for the process.

A permanganate solution supplied to the kerogen may be tailored tocomplement chemical features of the oil shale formation, or the chemicalfeatures of a formation fluid, if present in the formation. In oneembodiment, the permanganate solution has a pH of at least 7, or in thepH range of from 7 to 9. In some such embodiments, the desiredpermanganate solution pH is achieved with the addition of an alkalinematerial. Exemplary alkaline materials which are useful include, forexample at least one of carbonates, bicarbonates, oxides, and hydroxidesof, for example, sodium, potassium, calcium, and magnesium. Anillustrative extractive fluid contains a molar ratio of carbonate tobicarbonate in the range from 5:95 to 95:5; or in the range from 10:90to 90:10; or in the range from 25:75 to 75:25.

In the process, the permanganate oxidant in contact with the kerogenforms organic acids and manganese oxides as reduced forms of themanganese oxidant, including reduced forms such as MnO₂, Mn²⁺ and MnO₄⁻.

In one embodiment, a surfactant or mixture of surfactants are providedto the kerogen in the subsurface shale. The surfactant can be anysubstance that reduces surface tension of the fluid, or reducesinterfacial tension between two liquids, or one liquid and thesurrounding formation. The surfactant can also be chosen, for example,to increase the accessibility of the fluid to the kerogen, and/or toincrease the mobility of the reaction products from the kerogen, and/orto increase the effectiveness of the fluid for absorbing the reactionproducts. Suitable surfactants for use in the present fluids may beselected from nonionic, anionic or amphoteric surfactants.

Reactive Fluid

In one embodiment, the permanganate oxidant is combined with a solventor carrier fluid to form a reactive fluid for passing to the kerogen inthe subsurface shale formation. The reactive fluid is designed andformulated to provide oxidant to the formation fluid, and to maintainthe integrity of the oxidant until it is in contact with the kerogen. Inone embodiment, the reactive fluid is further formulated to mobilizeorganic acids, which are formed during kerogen conversion, either as asuspension of colloidal kerogen fragments or as a solution of dissolvedorganic acids.

The reactive fluid includes a carrier fluid that may be either anaqueous solvent, or an organic solvent, or combinations thereof. Thecarrier fluid may be provided from any suitable source, such as, forexample, one or more of municipal water; surface water or water from asubsurface aquifer; bitter water sources with high pH levels, andcontaining quantities of one or more of carbonates, bicarbonates,oxides, and hydroxides, which are recovered from subsurface aquifers;reactive water; and recycle aqueous fluids from the kerogen conversionand extraction process. In one embodiment, the recycle aqueous fluidcontains organic acids which remain in solution following the step ofisolating at least a portion of the organic acids from the mobilekerogen-based product. In one embodiment, the recycle aqueous fluidcontains organic acids from the isolating step that are added back tothe recycle aqueous fluid as surfactants. In one such embodiment, therecycle aqueous fluid contains at least 0.1 wt. % organic acids,including, for example, at least 0.5 wt. % organic acids; or at least1.0 wt. % organic acids.

At least a portion of the reactive fluid may be prepared in surfacefacilities. It may be desirable to locate the preparation of the aqueousreactive fluid such that the prepared fluid is conducted by pipelinetransport from the preparation location to the injection well forproviding the fluid to the subsurface shale.

The permanganate oxidant concentration in the reactive fluid isdetermined by a number of factors, including the stability andreactivity of the oxidant at the conditions of the subsurface formation,the nature of the inorganic component of the subsurface shale, and thedesired products from the kerogen conversion reactions. In oneembodiment, the oxidant concentration in the reactive fluid is kept at alow level to reduce the secondary oxidation reactions of the organicacids which have been liberated from the kerogen. In one embodiment, thereactive fluid as provided to the subsurface shale formation contains inthe range from 0.1 wt. % to 100 wt. % oxidant; or in the range from 0.1wt. % to 40 wt. % oxidant; or in the range of 0.1 wt. % to 25 wt. %oxidant, or in the range from 1 wt. % to 15 wt. %. In one embodiment,the reactive fluid contains from 0.1 wt. % to 40 wt. % of the oxidant ina carrier fluid selected from the group consisting of an aqueous fluid,an ethanol fluid or combinations thereof.

The pH of the reactive fluid containing the permanganate oxidant has apH in a range from 7 to 14; in one embodiment, from 7 to 9. Achievingthe desired pH may include the addition of an alkaline material to thereactive solution. Exemplary alkaline materials which are usefulinclude, for example at least one alkaline material selected fromcarbonates, bicarbonates, oxides, and hydroxides of, for example,sodium, potassium, calcium, and magnesium. An illustrative reactivefluid contains a molar ratio of carbonate to bicarbonate in the rangefrom 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the rangefrom 25:75 to 75:25.

In one embodiment, the reactive fluid comprises a surfactant or mixtureof surfactants for provision to the kerogen in the subsurface shale. Thesurfactant can be any substance that reduces surface tension of thefluid, or reduces interfacial tension between two liquids, or one liquidand the surrounding formation. The surfactant can also be chosen, forexample, to increase the accessibility of the fluid to the kerogen,and/or to increase the mobility of the reaction products from thekerogen, and/or to increase the effectiveness of the fluid for absorbingthe reaction products. Suitable surfactants for use in the presentfluids may be selected from nonionic, anionic or amphoteric surfactants.

In one embodiment, the reactive fluid further comprises at least onephase transfer catalyst to enhance the chemical interaction betweenkerogen and oxidant, for increasing the reaction rate of the oxidant. Inone such embodiment, the phase transfer catalyst is selected from thegroup consisting of tetraethyl ammonium chloride and the crown ether1,4,7,10,13,16-hexaoxacyclooctadecane (18-crown-6 crown ether).

Formation Fluid

In the process, kerogen in subsurface shale is contacted with thepermanganate oxidant. In one embodiment, the oxidant contacts thekerogen in the subsurface shale in liquid medium, otherwise termed a“formation fluid”. In this case, at least a portion of the liquid mediummay be the reactive fluid that is prepared in surface facilities andpassed to the subsurface shale through an injection well. Likewise, atleast a portion of the liquid medium may be formation water that isnaturally occurring in the subsurface shale.

Reaction conditions and the composition of the formation fluid forconverting kerogen into the mobile kerogen-based product are selected tominimize the environmental effects of the process for extracting thekerogen-based product; and/or to maximize the conversion of kerogen intothe mobile kerogen-based product; and/or to maximize the selectivity ofthe reaction to C₁₀+ organic acids; and/or to minimize the conversion ofthe kerogen to CO₂.

The step of contacting the kerogen with the formation fluid in thesubsurface shale is generally conducted at or near a natural formationtemperature. In one embodiment, the contacting occurs at a temperaturein the range of between 0° C. and 200° C. In one embodiment, thecontacting occurs at a temperature of less than 200° C. above thenatural formation temperature. In one embodiment, the contacting occursat a temperature below a pyrolysis temperature of the kerogen. In onesuch embodiment, the contacting occurs at a temperature in one thefollowing ranges: between 10° C. and 150° C.; between 20° C. and 100°C.; or between 25° C. and 75° C. In one such embodiment, the formationfluid contacts the kerogen at a temperature of less than 150° C.; orless than 100° C.; or even less than 75° C. above the natural formationtemperature. In a non-limiting specific example, the contacting isconducted at a temperature of less than 50° C. above the naturalformation temperature. In one embodiment, the contacting is conductedunder conditions in which no added heat is supplied to the formationfluid and/or to the subsurface shale in contact with the formationfluid. In one embodiment, if heat is supplied during the kerogenconversion to meet the above-mention target temperature, it is suppliedsolely from exothermic chemical processes within the kerogen and/orwithin the subsurface shale in contact with the kerogen. As such, noexternal heating is provided. The contacting occurs at temperature belowpyrolysis temperature of the kerogen.

Generally, the kerogen in the subsurface shale is contacted with theformation fluid at or above natural formation pressure (i.e., thepressure of the subsurface shale formation in the region that includesthe kerogen), so as to maintain or increase the accessibility of thefluids to kerogen in the subsurface shale formation. In one suchembodiment, the formation fluid is provided to the formation at apressure above fracture pressure, so as to increase the accessibility ofthe formation fluid to the kerogen in the formation. Methods fordetermining the formation pressure and the formation fracture pressureare known. In one such embodiment, the formation fluid is provided tothe formation at a pressure of up to 1000 psig; or up to 750 psig; or upto 500 psig; or even up to 250 psig above the natural formationpressure. The natural formation pressure, as used herein, is thepressure of the subsurface shale formation, in the region of thekerogen, prior to human intervention with or in the formation. Methodsfor determining an natural formation pressure are known.

In one embodiment, the process includes contacting the kerogen in thesubsurface shale with an oxidant. The mobile kerogen-based productcomprises reaction products from the reaction of the oxidant with thekerogen. The step of creating a mobile kerogen-based product involves achemical modification of the kerogen. The chemical modification involvesat least some cracking of the kerogen, generating smallerkerogen-derived molecules that are correspondingly more mobile.

In one embodiment, a fluid, such as a formation fluid in contact withthe kerogen, facilitates the kerogen reactions. The formation fluid maybe caused to flow through the subsurface shale formation for an amountof time needed to reach a certain objective, e.g., a reduced oxidantconcentration target in the formation fluid, or a target amount ofmobile reaction products produced, or a target extent of conversion ofthe kerogen. The formation fluid may then be caused to flow through thesubsurface shale formation for an amount of time need to reach a certainobjective, e.g., a target removal of mobile reaction products, or atarget concentration of mobile reaction products in the formation fluid.In another embodiment, the process of providing reactive fluid to thekerogen may be a cyclic process, repeated until a target level ofkerogen conversion is achieved. In another embodiment, a formation fluidis suitable for both converting kerogen in the subsurface shale andabsorbing the reaction products to form the mobile kerogen-basedproduct, which is recovered for isolating the organic acids containedtherein.

In one embodiment, pumping is used to transport the mobile kerogen-basedproduct out of the subsurface shale formation, wherein such pumping canbe performed using techniques known to those of skill in the art.Conventional oil field practices (both flowing gas and pumping fluids,e.g., rod pumps, electrical submersible pumps, progressive cavity pumps,etc.) can be modified to provide reliability in a given producingenvironment. For example, modifications may require changes inmetallurgy, pressure limitations, elastomeric compositions, temperaturerating, and the like.

Production could use any standard producing process such as, but notlimited to, at least one well penetrating into the subsurface shaleformation as an injection well for providing fluids to the subsurfaceshale formation and at least one well penetrating into the subsurfaceshale formation as a production well for producing fluids from theformation, Huff-n-Puff (i.e., a single well is used as both the producerand injector), water flooding, steam flooding, polymer flooding, solventextraction flooding, thermal processes, diluent addition, steam assistedgravity drainage (SAGD), and the like.

The formation fluid is a fluid, such as an aqueous fluid, which is incontact with the kerogen in the subsurface shale formation. In oneembodiment, at least a portion of the formation fluid is supplied as areactive fluid from surface facilities. In one embodiment, the reactivesolution provided to the kerogen establishes a formation fluid incontact with the kerogen, or it supplements a formation fluid which isalready established, or which is naturally occurring in the subsurfaceshale formation in contact with the kerogen. In one embodiment, theformation fluid is derived from, or results from, formation water thatnaturally occurs within the formation. The formation fluid may bepresent and in contact with the kerogen in the formation, in smallquantities which merely wet the solid surfaces in the formation.Alternatively, the formation fluid may be present in sufficientquantities to flood the formation; or in any quantity between the wettedor flooded states.

The formation fluid is any fluid (including mixtures) that can, eitherby itself, with an agent combined with the fluid, or in combination witha solvent, chemically modify the kerogen so as to render it mobile andtherefore extractable. In one embodiment, the formation fluid comprisesan oxidant having a chemical property of oxidation. In one aspect, theoxidant is active for breaking chemical bonds in kerogen. In one aspect,the oxidant is active for breaking carbon-oxygen bonds in kerogen. Inone aspect, the oxidant is active for breaking carbon-carbon doublebonds in kerogen. In one aspect, the oxidant has a low activity forbreaking carbon-carbon single bonds in kerogen. In one aspect, theoxidant is active for producing mobile reaction products from kerogen.In one aspect, the oxidant is active for facilitating the mobilizationof hydrocarbons from kerogen in subsurface shale.

In one embodiment, at least a portion of the aqueous formation fluid isrecovered as a naturally occurring aqueous basic solution from one ormore subsurface aquifers; at least a portion of the naturally occurringaqueous basic solution may occur with the subsurface shale. Suitablenaturally occurring aqueous basic solutions have a pH of at least 7; orat least 8; or at least 8.5; or in the range of between 7 and 14. In onesuch embodiment, the naturally occurring aqueous basic solution floodsthe subsurface shale and is available for absorbing the convertedproducts, or is caused to flow from its source to the subsurface shalethat contains the converted products. In another such embodiment, thenaturally occurring aqueous basic solution is recovered from the aquiferthrough a well drilled into the aquifer. The recovered solution,optionally with added components, such as added carbonates,bicarbonates, oxides and/or hydroxides and/or added surfactants, ispassed through an injection well into the subsurface shale resource forextracting the hydrocarbon products present therein.

In one embodiment, at least a portion of the alkaline materials,including one or more of carbonates and bicarbonates and oxides andhydroxides, that are present in the formation fluid are derived fromnaturally occurring deposits. Naturally occurring sources of thealkaline materials are known. The following carbonate and bicarbonateminerals are non-limiting examples.

-   -   Sodium sesquicarbonate (Na₃H(CO₃)₂) is either a double salt of        sodium bicarbonate and sodium carbonate, or an equimolar mixture        of those two salts, with varying quantities of water of        hydration.    -   The dihydrate, Na₃H(CO₃)₂.2H₂O, occurs in nature as mineral        trona.    -   Thermonatrite is a naturally occurring mineral form of sodium        carbonate Na₂CO₃.(H₂O).    -   Natron is a naturally occurring mixture of sodium carbonate        decahydrate (Na₂CO₃.10H₂O) and sodium bicarbonate (NaHCO₃),        often with relatively minor quantities of sodium chloride and        sodium sulfate.    -   Nahcolite is a naturally occurring form of sodium bicarbonate        (NaHCO₃).    -   Shortite is a naturally occurring form of a sodium-calcium        carbonate mineral (Na₂Ca₂(CO₃)₃).

As a non-limiting illustrative example, a reactive fluid is passed, viaan injection well, to a source of the alkaline materials within or nearthe subsurface shale resource to dissolve the alkaline materials intothe formation fluid before being passed to the formation fluid in thesubsurface shale formation. In some cases, liquid water is injectedunder sufficient pressure into the carbonate and/or bicarbonate sourceto cause the water to wet at least a portion of the source and todissolve at least some of the carbonate and/or bicarbonate into thewater.

In one such embodiment, the water that contains the dissolved alkalinematerials is caused to flow from the deposit in which it occurs to thesubsurface shale resource that contains the converted hydrocarbonproducts. In another such embodiment, the solution of the dissolvedalkaline materials is recovered from the aquifer through a well drilledinto the aquifer. The recovered solution, optionally with addedcomponents, such as added carbonates, bicarbonates, oxides and/orhydroxides, or added surfactants, is passed through an injection wellinto the subsurface shale resource for extracting the hydrocarbonproducts present therein.

In another such embodiment, at least a portion of the water isintroduced to the deposit of alkaline materials as steam, and in somecases as superheated steam, to facilitate the dissolution of thealkaline materials into the water. At least some of the steam condenses,dissolves the alkaline materials, and is passed to the subsurface shaleformation.

In one such embodiment, the process includes contacting the kerogen withthe fresh formation fluid, and producing a spent formation fluid whichcontains less than 20 wt. %, or less than 10 wt. %, or less than 5 wt. %of the oxidant, or less than 1 wt. % of the oxidant, or less than 0.5wt. % of the oxidant, or less than 0.1 wt. % of the oxidant. In oneembodiment, the reactivity of the formation fluid is enhanced byaddition of a combination of oxidants.

The formation fluid has a pH that is generally selected to balance thestability, reactivity and solubility of the oxidant in the formationfluid with the solubility and stability of the kerogen reaction productsin the formation fluid. Oxidants that exhibit high kerogen conversionactivity in aqueous fluid at pH values of at least 7 are generallysupplied to the subsurface shale formation in a basic solution (i.e.,basic formation fluid). In one such embodiment, the desired reactivesolution pH is achieved with the addition of an alkaline material to thereactive solution. Exemplary alkaline materials which are usefulinclude, for example at least one alkaline material selected fromcarbonates, bicarbonates, oxides, and hydroxides of, for example,sodium, potassium, calcium, and magnesium. An illustrative formationfluid contains a molar ratio of carbonate to bicarbonate in the rangefrom 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the rangefrom 25:75 to 75:25.

The formation fluid may be further treated with acids or bases to tailorthe pH of the formation fluid, to, for example, account for thesolubility and/or stability of the oxidant or to increase the solubilityof the mobile organic acids produced during the kerogen conversionprocess. In one embodiment, the formation fluid that is supplied to thesubsurface shale has a pH of less than or equal to 7, or in the rangefrom 1.5 to 6.5. In another embodiment, the formation fluid that issupplied to the subsurface shale has a pH of at least 7. In this case,the pH of the formation fluid is selected both to facilitate thesolubility of organic acids in the formation fluid and to facilitate thechemical stability and reactivity of the oxidant at subsurface shaleformation conditions. In one embodiment, the formation fluid is suppliedto the subsurface shale formation at a pH in the range of 7 to 14; or inthe range of 7 to 9.

The formation fluid may further contain other components for, e.g.,enhancing the reactivity of the reactive components, for enhancing theaccessibility of the formation fluid to the kerogen, or for enhancingthe dissolution, absorption, or dispersion of mobile reaction productsinto the formation fluid.

Formation Water

Formation water, a naturally occurring liquid source within at leastsome kerogen deposits in subsurface shale, is a suitable source for atleast a portion of the formation fluid used for converting kerogen andrecovering useful products. Some kerogen deposits are directly incontact with formation water. Other kerogen deposits are wetted byresidual formation water. In other deposits, the formation water aquiferis remote from the kerogen deposit which is being exploited forrecovering useful products. When sufficient formation water is present,either in contact with the kerogen or sufficiently near the kerogendeposit to be passed to the kerogen deposit, the formation water may beuseful as a source of at least some of the components of the formationfluid.

Certain subsurface shale formations, such as the Green River Shale, arecharacterized by limestone deposits that produce formation wateraquifers having a basic pH (i.e., pH greater than 7). In one embodiment,formation waters are useful as a source or a component of the formationfluid. In an exemplary process, oxidant is provided to formation waterto form the formation fluid, which facilitates the conversion of kerogenat a temperature in the range of between 0° C. and 200° C. to formorganic acids.

In the case in which the kerogen is naturally in contact with formationwater that is suitable for the process, the process includes providingan oxidant to the formation water to produce the formation fluid. Forformations in which the formation water having the desired properties isin an aquifer separate from (or remote to) the kerogen, the formationwater may be caused to pass from the remote aquifer to the kerogen. Thismay be achieved, for example, by causing the formation water to passfrom the remote aquifer through a borehole which is drilled into theformation water aquifer. In one embodiment, the formation water ispassed through the borehole to surface facilities, and processed byaddition of oxidant and then provided to the kerogen. In anotherembodiment, the formation water is passed through the borehole directlyto the kerogen in the subsurface shale formation.

When at least a portion of the mobile kerogen-based product is withdrawnfrom the formation, additional formation fluid in the region of thekerogen is produced by flowing additional formation water to, andcontacting, the kerogen in the subsurface shale formation to replace thefluid that was withdrawn. In one embodiment, one or more oxidants areprovided to the additional formation water that flows into contact withthe kerogen.

As stated, a suitable formation water desirably has a pH of at least 7,or in the range from 7 to 14, or in the range from 12 to 14. In oneembodiment, the formation water comprises an alkaline material selectedfrom the group consisting of a carbonate, a bicarbonate, an oxide, and ahydroxide. An exemplary alkaline material is selected from the groupconsisting of sodium carbonate, sodium bicarbonate, and sodiumhydroxide, or mixtures thereof.

In the process, a formation fluid which comprises formation water and anoxidant contacts the kerogen for a time sufficient to reduce the oxidantconcentration to a target low level. In one embodiment, the formationfluid is caused to contact with kerogen for a time sufficient to reducethe oxidant concentration in the formation fluid to less than 0.5 wt. %,or for a time sufficient to reduce the oxidant concentration in theformation fluid to less than 0.1 wt. %, or to reduce the oxidantconcentration in the formation fluid to less than 0.05 wt. %.

Use of formation water as a component of the formation fluid permits theuse of a cyclic process to convert kerogen and recover useful products.An exemplary cyclic process comprises the steps of: (a) providing anoxidant to formation water that is in contact with kerogen in subsurfaceshale to form a formation fluid; (b) contacting the kerogen in thesubsurface shale with the formation fluid at a temperature in the rangeof between 0° C. and 200° C. to form organic acids; (c) recovering atleast a portion of the organic acids from the subsurface shale formationto form a mobile kerogen-based product; (d) withdrawing at least aportion of the mobile kerogen-based product from the formation; (e)providing additional oxidant to the formation water in contact with thekerogen; and (f) repeating steps (b), (c), (d), and (e) a multiplicityof cycles, and converting at least 50 wt. % of the kerogen to organicacids. In one embodiment, the cyclic process also includes recyclesteps, including: isolating at least a portion of the organic acids fromthe mobile kerogen-based product; recovering an organic acid leanaqueous fluid; and providing at least a portion of the organic acid leanaqueous fluid, in combination with added oxidant, to the formation fluidin contact with the kerogen.

During the oxidation process, as the oxidant chemically oxidizes thekerogen to form reaction products, the concentration of the activeoxidant is itself reduced to a less active (in an oxidation sense) form.For example, within broad ranges it is known that permanganate isconverted as follows during redox reactions in model systems:

-   -   (a) In an acidic solution, permanganate(VII) is reduced to the        colorless +2 oxidation state of the manganese(II) (Mn2+) ion:        8H⁺+MnO₄ ⁻+5e⁻→Mn₂ ⁺+4H₂O;    -   (b) In a strongly basic solution, permanganate(VII) is reduced        to the green +6 oxidation state of the manganate, MnO₄ ²⁻: MnO₄        ⁻+e⁻→MnO₄ ²⁻; and    -   (c) In a neutral medium, permanganate (VII) is reduced to the        brown +4 oxidation state of manganese dioxide: MnO₂: 2H₂O+MnO₄        ⁻+3e⁻→MnO₂+4OH⁻.

In the process, a formation fluid which comprises formation water and anoxidant contacts the kerogen for a time sufficient to reduce thepermanganate oxidant concentration to a target low level. In oneembodiment, the formation fluid is caused to contact with kerogen for atime sufficient to reduce the permanganate oxidant concentration in theformation fluid to less than 50 wt. %, or for a time sufficient toreduce the oxidant concentration in the formation fluid to less than 25wt. %, or for a time sufficient to reduce the oxidant concentration inthe formation fluid to less than 10 wt. % of the original concentration.

Organic Acids

In the process, the oxidant contacts the kerogen to form organic acids.The organic acids may be saturated, unsaturated, or polyunsaturated. Inone embodiment, at least a portion of the organic acids are branched;the branching functional groups may be paraffinic, olefinic or cyclic.Cyclic branching functional groups may be saturated, unsaturated oraromatic. The organic acids may also contain nitrogen and/or sulfuratoms. In one embodiment, the organic acids are monoacids (a singlecarboxyl functional group in non-ionized or ionized form per molecularunit), or diacids (two carboxyl functional groups per molecular unit),or triacids (three carboxyl functional groups per molecular unit), orhigher. Mobile kerogen fragments, including kerogen fragments having amolecular mass of up to 12,000 to 15,000 Daltons or higher, may havemultiple carboxyl functional groups that serve to render these fragmentsmobile in an aqueous medium. These high molecular weight fragments aregenerally mobilized in the fluid as a slurry, rather than as a puresolution. Under some conditions, the organic acids are present as salts.An exemplary sodium salt of an organic acid contains the carboxylfunction group represented by —COO—Na+.

The molecular weight of the organic acids covers a very wide range,including from low molecular weight acids, such as the monoacid, aceticacid, and the diacid, oxalic acid, to high molecular weight kerogenfragments, having a molecular mass of up to 15,000 daltons or higher,and comprising at least one carboxylic acid functional group. In oneembodiment, these kerogen fragments have a lower molecular mass than thenaturally occurring kerogen itself, but with the general characteristicchemical and conformational complexity of the kerogen structures fromwhich they are derived. Such high molecular weight acids are soluble in,or otherwise mobile in, high pH solutions, such as solutions having a pHof at least 7.5; or at least 8.0; or at least 8.5; or in the range ofbetween 8.5 and 14. Accordingly, in one embodiment, at least 10 wt. %,or at least 30 wt. %, or at least 50 wt. % of the organic acids in themobile kerogen-based product is in the C₃₅+ range. In one embodiment, atleast 20 wt. % of the C₃₅+ organic acids has a molecular mass number ofgreater than 1000 daltons.

In one embodiment, a significant fraction of the organic acids are alsoin the C₆ to C₂₀ carbon number range. In one such embodiment, at least10 wt. % of the organic acids in the mobile kerogen-based product are inthe C₆ to C₂₀ range, or in the C₆ to C₁₆ range, or in the C₈ to C₁₄range or in the C₈ to C₁₂ range. In one such embodiment, at least 20 wt.% of the C₃₅− organic acids is in the C₈ to C₁₂ range. Maintainingreaction conditions to minimize the amount of oxidation of the kerogenwhile ensuring that the reaction products are mobile has the benefit ofdecreased oxidant consumption, minimum formation of carbon dioxideproduct, and reduced hydrogen consumption during the hydrogenation ofthe acid products during an upgrading step.

In general, the mobile kerogen-based product contains at least one ofthe following organic acids and hydrocarbons: monoacids, diacids,branched monoacids, branched diacids, isoprenoid acids, iopanoic acids,gamma keto acids, keto monoacids, keto diacids, and n-alkanes. In therange from 10 wt. % to 90 wt. % of the C₃₅− organic acids in the mobilekerogen-based product are monoacids. In one such embodiment, in therange from 10 wt. % to 50 wt. % of the C₃₅− organic acids are monoacids.Likewise, in the range from 10 wt. % to 90 wt. % of the C₃₅− organicacids in the mobile kerogen-based product are diacids. In oneembodiment, at least 30 wt. % of the C₃₅− organic acids are diacids. Inone such embodiment, in the range from 30 wt. to 90 wt. % of the C₃₅−organic acids are diacids. In one embodiment, in the range from 1 wt. %to 30 wt. %, or in the range from 1 wt. % to 20 wt. %, or in the rangefrom 1 wt. % to 10 wt. % of the C₃₅− organic acids in the mobilekerogen-based product are gamma keto acids.

Mobile Kerogen-Based Product

In one embodiment, the organic acids are mobilized to produce a mobilekerogen-based product. The mobile kerogen-based product generallycontains at least 1 wt. % organic acid derived products; or at least 2wt. % organic acid derived products; or at least 5 wt. % organic acidderived products. In some situations, the organic acid derived productsare present in the product at a concentration in the range from 5 wt. %to 50 wt. %; or at a concentration in the range from 10 wt. % to 40 wt.%. The ratio of organic acid derived products to other hydrocarbons inthe mobile kerogen-based product will depend on the source of thehydrocarbons, but is expected to range from 10% organic acid derivedproducts to 100 wt. % organic acid derived products.

It is believed that organic acids comprise a significant portion of thekerogen based product formed from reaction of oxidants on the kerogen.However, when the organic acids are mobilized, organic acid reactionproducts may be involved. As such, mobilization of the organic acids mayinvolve, for example, neutralization, dimerization and esterification ofthe organic acids.

Thus, in one embodiment, the mobile kerogen-based product may compriseorganic acid as organic acids. In one embodiment, the mobile kerogenbased product may comprise organic acids as organic acid anionicmoieties (RCOO—) or organic acid salts (RCOO-M+). The cation (M+) of theorganic acid salts can be cations that are naturally present in theformation, for example, sodium, potassium, calcium and magnesium. In oneembodiment, the mobile kerogen based product may comprise organic acidsas esters. Exemplary esters include methyl and ethyl esters. In oneembodiment, the mobile kerogen-based product may comprise organic acidsin a form selected from the group consisting of organic acids, organicacid salts, anionic organic acid moieties, organic acid esters, andmixtures thereof.

The mobile kerogen-based product may further include components tofacilitate extraction of reaction products from the kerogen. Thesecomponents may include, for example, one or more of a solvent or solventmixture; alkaline materials; surfactants; organic and/or inorganicacids; organic and/or inorganic bases; soluble organic compounds such asalcohols, ethers, esters, ketones, aldehydes, and the like. In oneembodiment, the mobile kerogen-based product is an aqueous phase fluidcontaining the organic acid derived products, which are dissolved,dispersed, or suspended in the aqueous phase fluid.

In one embodiment, the organic acid reaction products are mobilized at apH of at least 7, or at a pH in a range from 7 to 14. The pH of themobile kerogen-based product into which organic acids are extracted,following conversion of the kerogen, may, under some conditions, have apH in a range from 7 to 14 by reason of contact with alkaline materialsin the subsurface shale. Alternatively, at least a portion of thealkaline materials present in mobile product may be provided fromsurface facilities. Exemplary alkaline materials which are usefulinclude, for example at least one alkaline material selected fromcarbonates, bicarbonates, oxides and hydroxides of, for example, sodium,potassium, calcium, and magnesium. In an illustrative process, organicacids are extracted from kerogen in contact with alkaline materials,such that a molar ratio of carbonate to bicarbonate in the range from5:95 to 95:5; or in the range from 10:90 to 90:10; or in the range from25:75 to 75:25.

The pH of the mobile fluid in contact with the kerogen, for extractingorganic acid reaction products, is tailored for the particular organicacids to be extracted into and absorbed by the mobile product. Lowmolecular weight acids are soluble in fluids having a pH at or near theneutral range (i.e. a pH in a range from 6 to 8). High molecular weightkerogen fragments may be mobilized as a colloid or slurry in the mobileproduct at a pH in a range from 12 to 14.

Formation of the mobile kerogen-based product may be facilitated by thepresence of one or more organic solvents. Suitable organic solvents areselected to remain in a liquid phase, and to maintain the reactionproducts in solution, at temperature and pressure conditions within thesubsurface shale. In one embodiment, a suitable organic extractant isone in which at least a portion of the organic acids are soluble.Exemplary organic extractants contain aromatic compounds such asbenzene, toluene and xylene; nitrogen containing solvents such as NMP,amines, and amides; oxygenates containing compounds such as acids,ketones, esters and aldehydes; paraffins and naphthenes; olefins and thelike. Illustrative organic solvents include refinery streams boiling inthe range from 100° C. to 500° C., such as diesel fuel or naphtha.

In one embodiment, the mobile kerogen-based product may include carbondisulfide. Hydrogen sulfide, in addition to other sulfur compoundsproduced from the formation, may be converted to carbon disulfide usingknown methods. Suitable methods may include oxidation reaction of thesulfur compound to sulfur and/or sulfur dioxides, and by reaction ofsulfur and/or sulfur dioxides with carbon and/or a carbon containingcompound to form the carbon disulfide formulation.

Extraction

The step of extracting and absorbing the organic acid reaction productsinto the mobile kerogen-based product fluid is generally conducted at ornear the natural formation temperature. In one such embodiment, theabsorbing is conducted at a temperature of less than 200° C.; or lessthen 150° C.; or less than 100° C.; or even less than 75° C. above thenatural formation temperature. In one such embodiment, the absorbing isconducted at a temperature in the range of between 0° C. and 200° C.; orin the range of between 10° C. and 150° C.; or in the range of between20° C. and 100° C.; or even in the range of between 25° C. and 75° C. Ina non-limiting specific example, the absorbing is conducted at atemperature of no greater than 50° C. above the natural formationtemperature.

In one embodiment, the absorbing is conducted under conditions in whichno added heat is supplied to the formation fluid and/or to thesubsurface shale in contact with the formation fluid. In one embodiment,if heat is supplied during the kerogen conversion to meet theabove-mention target temperature, it is supplied solely from exothermicchemical processes within the kerogen and/or within the subsurface shalein contact with the kerogen. In one embodiment, the absorbing isconducted at a temperature below pyrolysis temperature.

Generally, the organic acids in the subsurface shale are absorbed intothe mobile kerogen-based product at or above formation pressure (i.e.,the pressure of the subsurface shale formation in the region thatincludes the kerogen), so as to maintain or increase the accessibilityof the fluids to kerogen in the subsurface shale formation. In oneembodiment, the organic acid reaction products are extracted from thekerogen and into the mobile kerogen-based product at a pressure of up to1000 psig above the formation pressure; or up to 750 psig above theformation pressure; or up to 500 psig above the formation pressure; oreven up to 250 psig above the formation pressure. Injection of a gasinto the formation may result in a viscosity reduction of some of thehydrocarbon products in the formation.

In one embodiment, a formation fluid is maintained in contact with thekerogen until a target amount of mobile reaction products have beenabsorbed by the formation fluid, i.e., for a time sufficient to producea mobile kerogen-based product which contains at least 1 wt. % organicacids; or at least 2 wt. % organic acids; or at least 5 wt. % organicacids. Progress toward reaching the target amount may be monitored, forexample, by withdrawing the fluids to the surface for analysis, byanalyzing the fluids in the subsurface shale formation, or by analyzingthe fluids in a well extending into the formation.

In one embodiment, a formation fluid that is suitable for mobilizing thereaction products has a pH of greater than a target value, e.g., greaterthan 7, and the formation fluid is maintained in contact with thekerogen for a time during which the pH of the formation fluid remainshigher than the target minimum pH value. When the pH approaches or dropsbelow the target minimum, the formation fluid may be removed from thesubsurface shale, its alkaline content may be supplemented with alkalineadditives, or it may be supplemented with added reactive fluid.

Regeneration

In the process, a second oxidant is supplied to the formation fluid forregenerating the oxidation activity of the first oxidant. In embodimentsthat include using a permanganate as the first oxidant, kerogenconversion resulting from contacting the kerogen in the subsurface shalewith a permanganate oxidant, MnO₄ ⁻, forms organic acids and manganeseoxides, including manganese dioxide, MnO₂, manganese ion (Mn²⁺),manganate MnO₄ ²⁻, or combinations thereof. In one embodiment, a secondoxidant is supplied to regenerate the reduced forms of permanganate tomore oxidatively active forms. When permanganate oxidant is employed,any second oxidant, other than permanganate, that converts at least onereduced manganese form, such as manganese dioxide (MnO₂); or manganate(MnO₄ ²⁻); or Mn²⁺ to permanganate (MnO₄ ⁻) at a temperature in therange of 0° C. to 200° C. is suitable for the process. In oneembodiment, a second oxidant other than permanganate is supplied to themanganese oxides in the subsurface shale, such that at least a portionof manganese oxides are regenerated to at least one of MnO₄ ²⁻ or MnO₄⁻.

Suitable oxidants that are at least partially soluble in water may besupplied to the kerogen and/or the formation fluid in an aqueoussolution or slurry, or in a solution containing ethanol. In oneembodiment, solutions of the second oxidant contain at least 0.1 wt. %of the second oxidant. While the solution that provides the secondoxidant to the formation fluid may contain traces, or more, ofpermanganate, the second oxidant that is provided to the formation wateris an oxidant other than permanganate. In one embodiment, the secondoxidant is selected for its activity with respect to manganeseoxidation, its minimal environmental impact, and its relative stabilityduring transport to the formation fluid, and it's relatively low cost.Exemplary oxidants that meet at least one of these criteria includeperoxides, ozone and oxygen. Suitable peroxides include hydrogenperoxide, organic peroxides, including peroxy acids and hydroperoxides,and inorganic peroxides. The peroxides may be supplied to the kerogenfrom surface facilities, or generated in-situ by reaction of suitablereagents. Ozone, as well, may be supplied from surface facilities orgenerated in-situ, either by chemical reaction of suitable reagents orby equipment designed to generate ozone from gaseous oxygen. Oxygen,including an oxygen-containing gas, may also be used as the secondoxidant.

In one embodiment, regeneration of the oxidative activity of theformation fluid is conducted at a pH of at least 6, or in the range from6 to 8. In one embodiment, regeneration is conducted at a temperature inthe range from 0° C. to 200° C., or in the range from 20° C. to 150° C.In some such embodiments, the regeneration step includes flowing oxygenor an oxygen-containing gaseous mixture through the subsurface shale ata flow rate and at a partial pressure of oxygen such that a temperatureof the subsurface shale in the presence of the oxygen is no higher than100° C. above a natural reservoir temperature.

Second oxidants that are normally gaseous at a formation pressure and aformation pressure may be provided to the subsurface shale as a gaseousoxidant, such as, for example oxygen or an oxygen-containing gas. In oneembodiment, the oxygen is supplied as air to the formation fluid. Somecompression might be necessary to cause the air to flow through or intothe formation. In one embodiment, the air supplied to the formation as asecond oxidant contains added oxygen. In one embodiment, the airsupplied to the formation is slightly depleted in oxygen by, forexample, addition of extra nitrogen, helium, argon and the like to air.

In one embodiment, a secondary oxidant such as an oxygen-containinggaseous stream may be caused to flow through the subsurface shale toenhance and/or to maintain the oxidation activity of the formation fluidand of the first oxidant contained therein.

In an embodiment, a liquid solution having a pH of at least 7 andcontaining at least 0.02 wt. % to 25 wt. % is provided to kerogen insubsurface shale, or to a formation fluid in contact with the kerogen,for converting at least a portion of the kerogen to organic acids. Theconversion reactions are conducted in alkaline conditions, with the pHof the formation fluid in the range of at least 7, or in the range from7 to 9. Additional alkaline materials may be provided to the formationfluid during reaction to maintain the target pH. Suitable alkalinematerials include, for example at least one of carbonates, bicarbonates,oxides, and hydroxides of, for example, sodium, potassium, calcium, andmagnesium.

The first oxidant is maintained in contact with the kerogen for a timesufficient to cause conversion reactions to occur at a reactiontemperature in the range from 0° C. to 200° C. and at formationpressure. In one embodiment, the oxidant is maintained in contact withkerogen for at least 4 hours, or for at least 12 hours. In anotherembodiment, the formation fluid is maintained in contact with thekerogen for a period in the range from 1 hour to 45 days; in anotherembodiment from 12 hours to 20 days; in another embodiment from 1 day to7 days,

In one embodiment, the organic acids generated during kerogen conversionare mobilized in the formation fluid having a pH of at least 7, orhaving a pH of at least 12, or having a pH in the range from 12 to 14.Reaching the desired formation fluid pH may require supplying additionalalkaline materials. The mobile kerogen-based product comprising themobilized organic acids in the formation fluid is recovered for recoveryof organic acids and further processing.

In one embodiment, a liquid solution having a pH of at least 7 andcontaining in the range from 0.1 wt. % to 40 wt. % of a first oxidant iscaused to flow through subsurface shale which contains kerogen. Theflowing liquid solution causes the formation of organic acids throughconversion reactions of the kerogen. Organic acid products are mobilizedby the flowing liquid solution. The mobile kerogen-based productcomprising the mobilized organic acids in the formation fluid isrecovered for recovery of organic acids and further processing.

In one embodiment, a liquid solution having a pH of at least 7 andcontaining at least 0.1 wt. % to 40 wt. % of a first oxidant is providedto kerogen, or to a formation fluid in contact with the kerogen, for aperiod of at least 4 hours at a temperature in the range from 0° C. to200° C. for conversion of at least a portion of the kerogen to organicacids. A second oxidant is then provided to the formation fluid in theshale formation for regenerating the first oxidant. In one embodiment,the second oxidant is provided to the formation fluid at a pH in therange from 6 to 8. In one embodiment, the second oxidant is provided fora period of at least 4 hours. In one embodiment, the first oxidant isregenerated at a temperature in the range from 0° C. to 200° C. Beforethe second oxidant is provided to the formation fluid, it may bedesirable to reduce the pH of the formation fluid. Exemplary fluids forreducing the pH of the formation fluid include supplying CO₂ to theformation fluid.

Regenerating the oxidation activity of the formation fluid and of thefirst oxidant contained therein provides a formation fluid havingactivity for continuing conversion of the kerogen and formation oforganic acids. A cyclic process involving oxidation with a firstoxidant, and regeneration with a second oxidant may be conducted anumber of times. Recovery of organic acid products to produce a mobilekerogen-based product may be performed after each oxidation step, orintermittent throughout the cyclic process, or following a finaloxidation step at the conclusion of the cyclic process. The cyclicprocess may be conducted until a target amount of kerogen has beenconverted to mobilized products, i.e. until at least 50 wt. %, or atleast 60 wt. %, or at least 70 wt. %, or at least 80 wt. %, or at least90 wt. % of the kerogen in a region of the subsurface shale is convertedto mobilized products at the conclusion of the cyclic process.

Generally, multiple oxidation and product recovery cycles will benecessary to convert much of the kerogen to useful products. Thefollowing embodiments illustrate approaches to the cycle process. In oneembodiment, the process for extracting a kerogen-based product includesproviding a first oxidant to kerogen in subsurface shale, contacting thekerogen in the subsurface shale with the first oxidant to form organicacids, regenerating the first oxidant in the subsurface shale andrepeating the extraction, contacting and regenerating steps

Use of formation water as a component of the formation fluid permits theuse of a cyclic process to convert kerogen and recover useful products.An exemplary cyclic process comprises the steps of: (a) providing anoxidant to formation water that is in contact with kerogen in subsurfaceshale to form a formation fluid; (b) contacting the kerogen in thesubsurface shale with the formation fluid at a temperature in the rangeof between 0° C. and 200° C. to form organic acids; (c) recovering atleast a portion of the organic acids from the subsurface shale formationto form a mobile kerogen-based product; (d) withdrawing at least aportion of the mobile kerogen-based product from the formation; (e)providing additional oxidant to the formation water in contact with thekerogen; and (f) repeating steps (b), (c), (d), and (e) a multiplicityof cycles, and converting at least 50 wt. % of the kerogen to organicacids. In one embodiment, the cyclic process also includes recyclesteps, including: isolating at least a portion of the organic acids fromthe mobile kerogen-based product; recovering an organic acid leanaqueous fluid; and providing at least a portion of the organic acid leanaqueous fluid, in combination with added oxidant, to the formation fluidin contact with the kerogen.

In an exemplary process illustrated in FIG. 1, a reactive fluid isprepared in a preparation step 10 by mixing a first oxidant 2 with acarrier fluid 4, which may be aqueous or organic. Mixing devices formixing the first oxidant with the carrier fluid to make the reactivefluid are well known. In one embodiment, the first oxidant that is usedis effective for reacting with kerogen in an alkaline medium; underthese conditions the fluid may optionally be mixed with an alkalinematerial 6 to result in a fluid having a pH of at least 7.

The reactive fluid mixture 15 is passed to the kerogen in the subsurfaceshale formation in step 20 via a first (e.g., injection) well that hasbeen drilled to penetrate the subsurface formation to provide access tothe kerogen within the formation. The reactive fluid combines with afluid already present to form a formation fluid 25, in contact with thekerogen. In one embodiment, the subsurface shale formation has beenfractured to enhance the permeability of the shale to the first oxidantand to increase the accessibility of the kerogen component to thisfluid. In step 30 the first oxidant reacts with the kerogen to produce amobile kerogen-based product 35, which is produced to the surface instep 40. In one embodiment, multiple reactive fluid batches are providedto the formation fluid, prior to recovery of the mobile kerogen-basedproduct. The timing of each reactive fluid addition depends, at least inpart, on the progress of the kerogen conversion, and on the relativereactivity of the formation fluid in contact with the kerogen. Forexample, another reactive fluid batch may be provided to the formationfluid when the first oxidant concentration in the formation fluid fallsbelow 30 wt. %, or below 20 wt., or below 10 wt. % of the initial firstoxidant concentration in the fluid.

In the process, a second oxidant is prepared in step 60, and provided tothe kerogen through stream 65 for regenerating the first oxidant that isin contact with the kerogen in step 30. In one embodiment, the firstoxidant in contact with the kerogen is regenerated multiple times beforeanother batch of reactive fluid is provided to the formation fluid, orprior to recovery of the mobile kerogen-based product.

The mobile kerogen-based product 45 produced at the surface is treatedin step 50 for isolation and recovery of the organic acids and othermobile hydrocarbons 65. In one embodiment, at least a portion of thereaction products recovered from the kerogen conversion is absorbed bynaturally occurring alkaline enriched water that is present in thesubsurface shale. In the illustrative process shown in FIG. 1, theorganic acids 65 isolated in step 50 are subjected to further processingin step 70. In an embodiment of the illustrative process, an organicacid lean fluid 55 that is produced from the isolation step 50 isfurther treated in step 80 for recycle 85 to the subsurface shaleformation.

In an exemplary process illustrated in FIG. 2, and with furtherreference to the descriptions above relating to FIG. 1, in step 30 thefirst oxidant reacts with the kerogen to produce a mobile kerogen-basedproduct 35, which is produced to the surface in step 40. In the process,a second oxidant is prepared in step 60, and provided to the kerogenthrough stream 65 for regenerating the first oxidant that is in contactwith the kerogen in step 30. In one embodiment, the first oxidant incontact with the kerogen is regenerated multiple times before anotherbatch of reactive fluid is provided to the formation fluid, or prior torecovery of the mobile kerogen-based product.

Further in FIG. 2, a mobile kerogen-based product 35 is produced to thesurface in step 40. The mobile kerogen-based product 45 produced at thesurface is combined with an organic extractant 75 and the combinationtreated in step 50 for isolation and recovery of the organic acids andother mobile hydrocarbons 65. The organic acids 65 isolated in step 50are subjected to further processing in step 70. In an embodiment of theillustrative process, an organic acid lean fluid 55 that is producedfrom the isolation step 50 is further treated in step 80 for recycle 85to the subsurface shale formation. An acid lean extractant 105 from step75 is recycled and combined with organic extractant 75.

In an exemplary process illustrated in FIG. 3, a reactive fluid 115 isprepared in a preparation step 110 by mixing a first oxidant 102 with acarrier fluid 104, which may be aqueous or organic. Mixing devices formixing the first oxidant with the carrier fluid to make the reactivefluid are well known. In one embodiment, the first oxidant that is usedis effective for reacting with kerogen in an alkaline medium; underthese conditions the fluid may optionally be mixed with an alkalinematerial 106 to result in a fluid having a pH of at least 7.

The reactive fluid mixture 115 is passed to the kerogen in thesubsurface shale formation in step 120 via a first (e.g., injection)well that has been drilled to penetrate the subsurface formation toprovide access to the kerogen within the formation. The reactive fluidcombines with a fluid already present to form a formation fluid 125, incontact with the kerogen. In one embodiment, the subsurface shaleformation has been fractured to enhance the permeability of the shale tothe formation fluid and to increase the accessibility of the kerogencomponent to this fluid. In step 130, the first oxidant reacts with thekerogen to form organic acids 135.

An extractive fluid 145 is prepared in preparation step 140 by mixing analkaline material 142 with an aqueous carrier fluid 144 and optionallywith a surfactant 146. The extractive fluid 145 is combined into theformation fluid in step 150 for mobilizing the organic acids and to formthe mobile kerogen-based product 155, which is recovered. The mobilekerogen-based product 155 is treated in 160 to isolate organic acids175, which may be further processed in 170.

Isolating the organic acids further produces an organic acid lean fluid165, containing a reduced amount of organic acids. This fluid isprepared for return to the formation as a recycle fluid 185. Prior torecycling, the organic acid lean fluid may be conditioned in step 180for recycling to the formation. Typical conditioning steps include, forexample, removing inorganic salts, removing at least a portion of theremaining organic acids, including C₁ to C₁₀ organic acids, and removingother organic material from the fluid.

During some applications of the process, it may be desirable to contactkerogen in the subsurface shale with multiple formation fluidtreatments. With each treatment, an oxidant or a reactive fluidcontaining the oxidant is provided to the kerogen, for contacting thekerogen for a time sufficient to reduce the amount of oxidant to atarget low level. Generally, at least 10 wt. % of the oxidant isconsumed during each treatment. In one embodiment, at least 30 wt. %; inanother embodiment at least 50 wt. %; in another embodiment at least 70wt. % of the first oxidant is consumed during each treatment. At atarget condition set by the process (e.g. amount of the first oxidant incontact with the kerogen, extent of kerogen conversion, quality of thereaction products being produced), the second oxidant is provided to thekerogen to regenerate the first oxidant. In one embodiment, the cycle ofoxidizing the kerogen with the first oxidant and regenerating the firstoxidant with the second oxidant occurs multiple times before the mobilekerogen-based product is recovered and processed. In a secondembodiment, a cycle of oxidizing the kerogen with the first oxidant,regenerating the first oxidant with the second oxidant and recoveringthe mobile kerogen-based product is repeated multiple times. In a thirdembodiment, the second oxidant is supplied continuously to the kerogento maintain the first oxidant, in contact with the kerogen, at a desiredchemical activity level.

Generally, at least 30 wt. % of the kerogen is converted during themultiple treatment process. In one embodiment, at least 50 wt. %, or atleast 60 wt. %, or at least 70 wt. % of the kerogen is converted duringthe multiple treatment process.

In one embodiment, the process for extracting a kerogen-based productincludes causing the mobile kerogen-based product to flow through thesubsurface shale formation and to a second (e.g., production) well thathas been drilled to penetrate the subsurface formation to withdrawfluids from the formation. The formation fluid in contact with thekerogen causes some of the kerogen to react and form mobile reactionproducts, which are recovered from the subsurface shale to surfacefacilities for isolation and recovery of the mobile reaction products.In one embodiment, at least a portion of the mobile reaction productsare absorbed by the formation fluid and the resulting mobilekerogen-based product is recovered from the subsurface shale formation.

In one embodiment, the reactive fluid is caused to flow into thesubsurface shale formation from the injection well until a targetpressure higher than formation pressure is reached within the formation.The flow of the reactive fluid is then slowed or stopped and theresultant formation fluid mixture is maintained in contact with thekerogen, while converting kerogen in the subsurface shale to a mobilekerogen-based product and producing an oxidant-depleted formation fluid.Generally, at least a portion of the formation fluid mixture is removedfrom the kerogen when, for example, the reactivity of the formationfluid is depleted below a target amount, or the pH of the formationfluid has changed beyond a target pH range, or the amount of reactionproducts from kerogen conversion which has been absorbed by theformation fluid has met or exceeded a target amount. In one embodiment,the mobile kerogen-based product is at least partially removed from thesubsurface shale by reducing the pressure on the shale and permittingthe formation fluid to flow into a well for removal to the surface. Inone embodiment, the mobile kerogen-based product is at least partiallyremoved by displacement with additional reactive fluid added to theformation through an injection well.

In one embodiment, oxidant is maintained in contact with the kerogenuntil a target amount of mobile reaction products are produced and/orare absorbed into the formation fluid. Progress toward reaching thetarget amount may be monitored, for example, by withdrawing the fluidsto the surface for analysis, by analyzing the fluids in the subsurfaceshale formation, or by analyzing the fluids in a well extending into theformation. In one embodiment, the formation fluid is maintained incontact with the kerogen up to a target kerogen conversion. In one suchembodiment, the formation fluid is maintained in contact with thekerogen until at least 10 wt. %; or at least 30 wt. %; or at least 50wt. %; or at least 60 wt. %; or at least 70 wt. %; or even at least 80wt. % of the kerogen is converted to mobile reaction products. In oneembodiment, the formation fluid is maintained in contact with thekerogen for a time sufficient to reduce the concentration of the oxidantto a target value. Reducing oxidant concentration to low levels duringreaction facilitates the formation of high amounts of large mobilekerogen fragments and the formation of low amounts of CO₂ duringreaction of the kerogen. For example, less than 15 wt. %; or less than10 wt. %; or less than 5 wt. % of the kerogen is converted to CO₂ duringreaction with the formation fluid. In one such embodiment, the targetvalue with respect to the oxidant concentration in the formation fluidis less than 10 wt. %; or less than 7 wt. %; or less than 5 wt. %; or inthe range from 0.01 wt. % to 5 wt. % of the oxidant concentration of theformation fluid following addition of oxidant to the formation fluid. Inone embodiment, the formation fluid is maintained in contact with thekerogen for a period of greater than 1 hour; or in another embodimentfor a period of greater than 4 hours. In another embodiment, theformation fluid is maintained in contact with the kerogen for a periodin the range from 1 hour to 45 days; in another embodiment from 10 hoursto 20 days; in another embodiment from 1 day to 7 days, in order toreduce the concentration of the oxidant to a target value in the spentformation fluid.

The process may further include monitoring the extent of reaction of thekerogen. For example, a fluid sample, such as the formation fluid, maybe removed from the subsurface shale formation and analyzed for theoxidant component. Alternatively, the progress of the reaction may bemonitored using a downhole analyzer to determine the concentration ofthe oxidant component in the formation fluid. An analyzer suited todetermining a quantity of the oxidant may be inserted into, orintimately contacted with the fluids in the subsurface shale formation.

In other embodiments, the process further comprises monitoring thekerogen conversion using the amount of mobile reaction products in thesubsurface shale formation. As with the oxidant reactive componentdescribed above, the amount of mobile reaction products may bedetermined from an analysis of fluids recovered from the formation, orfrom a downhole analysis tool suited for analyzing the amount ofreaction products.

A variation (i.e., alternate embodiment) on the above-described processis the application of some or part of such above-described methods toalternative sources, i.e., low-permeability hydrocarbon-bearing (e.g.,oil and gas) formations, in situ coal, in situ heavy oil, in situ oilsands, and the like. General applicability of at least some of theabove-described invention embodiments to any hydrocarbon-bearingformation exists. Surface processing applications may include upgradingof oil shale, coal, heavy oil, oil sands, and other conventional oilswith asphaltenes, sulfur, nitrogen, etc.

Example

This example illustrates the effectiveness of potassium permanganate forproducing high molecular weight organic acids in reactions with kerogen.

Kerogen was separated from a sample of oil shale that contained kerogen.The separated kerogen was largely organic matter, with a small amount ofinorganic matter remaining from the inorganic substrate in which thekerogen originated. For this example, 2.50 grams of kerogen (organicmatter basis) was combined with a solution containing 0.5 g KMnO₄ in 100ml of 1% KOH solution. The kerogen/KMnO₄ mixture was stirred at 75° C.until the solution had lost its color, with no visual evidence of thepurple permanganate color remaining. In general, this reaction tookseveral hours, and up to 12 hours in some cases. The kerogen was thenallowed to settle, and was separated from the solution. The kerogen wasthen rinsed with two 75 ml aliquots of 1% KOH solution. The two rinsesolutions were set aside. The rinsed kerogen was then contacted withanother aliquot of KMnO4 solution, and the oxidation and washing stepswere repeated. After five successive KMnO₄ treatments, the kerogen waswashed with oxalic acid solution at low pH to dissolve MnO₂ which wasdeposited on the kerogen surface. The kerogen was then rinsed before thenext KMnO₄ treatment step. At the end of 17 KMnO₄ treatments, thekerogen was effectively consumed, and the permanganate color of thesolution no longer disappeared. All of the 1% KOH rinse solutionscollected from each treatment step were combined and acidified to pH2.0. High molecular weight acids in the acidified solution precipitatedfrom solution and were recovered. Low molecular weight acids in thesolution were extracted with methyl t-butyl ether and recovered byremoving the ether solvent.

FIG. 4 illustrates the gas chromatographic separation of the lowmolecular weight acids. A high proportion of the low molecular weight(i.e., C₃₅−) organic acids are in the C₈ to C₁₂ range. In particular,FIG. 4 shows carbon chain-size distribution of low molecular weightorganic acids (di-carboxylic acids and mono-carboxylic acids) in kerogenpermanganate oxidation products determined by gas chromatography—massspectrometry (GCMS) of their silyl derivatives. The high-pH aqueousreaction product solution was adjusted to ˜pH 2 and extracted withmethyl t-butyl ether solvent to yield low molecular weight organic acidsupon solvent removal. GCMS analysis showed these organic acids containprimarily straight (un-branched) alkyl chains. Hydroprocessing of thislow molecular weight organic acids product to remove oxygen and otherheteroatoms would provide the alkane mixture shown in the figure, wherethe number of carbon atoms in each of the major, straight-chain productpeaks is labeled. The carbon number distribution of products range from˜C₆ to ˜C₁₇ (with a maximum at C₉), covering the highly desirablegasoline, jet, and diesel transportation fuel hydrocarbon molecularweight range.

The high molecular weight (i.e., C₃₅+) organic acids were passed througha pyrolysis gas chromatograph, which thermally pyrolyzed the acids. FIG.5 is a gas chromatographic trace of the pyrolyzed acids. In particular,FIG. 5 shows carbon chain-size distribution of hydrocarbon productsformed by pyrolysis of high molecular weight organic acids in kerogenpermanganate oxidation products determined by pyrolysis gaschromatography—mass spectrometry (pyrolysis-GCMS). The high-pH aqueousreaction product solution was adjusted to ˜pH 2 resulting in theprecipitation of high molecular weight organic acids which werecollected, washed with deionized water, and dried under vacuum.Pyrolysis-GCMS analysis showed these high molecular weight organic acidsto yield primarily straight (un-branched) alkanes and alkenes uponheating to 500° C. in inert atmosphere. The number of carbon atoms ineach of the major, straight-chain product peaks is labeled in thefigure—each carbon number labels two peaks, consisting of an alkane andalkene pair, typical of pyrolysis/retort products. Hydroprocessing ofthe pyrolysis (retort) products shown in the figure, to remove alkenesand heteroatoms, would provide an alkane mixture with a carbon numberdistribution ranging from ˜C₅ to ˜C₃₁ (with a maximum at C₉), coveringthe highly desirable gasoline, jet, and diesel fuel hydrocarbonmolecular weight range, with a small proportion of product in the fueloil and lube oil hydrocarbon molecular weight range.

It is interesting to note that the profile of the pyrolyzed acids isvery similar to the profile of the low molecular weight acids. Inparticular, a high proportion of the pyrolyzed organic acids are also inthe C₈ to C₁₂ range.

Various modifications and alterations of this invention will becomeapparent to those skilled in the art without departing from the scopeand spirit of the invention. Other objects and advantages will becomeapparent to those skilled in the art from a review of the precedingdescription.

What is claimed is:
 1. A process for extracting a kerogen-based productfrom a subsurface shale formation comprising subsurface shale, theprocess comprising the steps of: a. providing a first oxidant to kerogenin subsurface shale; b. contacting the kerogen in the subsurface shalewith the first oxidant at a temperature in the range from 0° C. and 200°C. to form organic acids; c. mobilizing at least a portion of theorganic acids from the subsurface shale to produce a mobilekerogen-based product; and d. regenerating the first oxidant in thesubsurface shale.
 2. The process according to claim 1, furthercomprising providing the first oxidant to the kerogen combined with acarrier fluid selected from the group consisting of an aqueous fluid, anethanol fluid or combinations thereof.
 3. The process according to claim2, wherein the carrier fluid contains in the range from 0.1 wt. % to 40wt. % of the first oxidant.
 4. The process according to claim 2, whereinthe carrier fluid has a pH in the range from 7 to
 14. 5. The processaccording to claim 1, wherein the first oxidant is a permanganateoxidant.
 6. The process according to claim 5, wherein the permanganateoxidant is provided to the kerogen in aqueous solution that contains inthe range from 0.1 wt. % to 40 wt. % permanganate, expressed in terms ofthe weight of anhydrous permanganate salt dissolved in the solution. 7.The process according to claim 5, wherein the permanganate oxidant isselected from the group consisting of ammonium permanganate, NH₄MnO₄;calcium permanganate, Ca(MnO₄)₂; potassium permanganate, KMnO₄; andsodium permanganate, NaMnO₄.
 8. The process according to claim 1,further comprising providing the first oxidant to the kerogen at a pH ina range from 7 to
 14. 9. The process according to claim 8, furthercomprising maintaining the pH in the range from 7 to 14 by providing analkaline material selected from the group consisting of a carbonate, abicarbonate, an oxide and a hydroxide to the subsurface shale.
 10. Theprocess according to claim 8, further comprising providing the firstoxidant to the kerogen at a pH in a range from 7 to
 9. 11. The processaccording to claim 1, further comprising contacting the kerogen with thefirst oxidant for a period of at least 4 hours.
 12. The processaccording to claim 1, wherein the step of regenerating the first oxidantfurther comprises the steps of: providing a second oxidant to thesubsurface shale; and regenerating the first oxidant in the subsurfaceshale with the second oxidant.
 13. The process according to claim 12,further comprising providing the second oxidant to the kerogen in acarrier fluid selected from the group consisting of an aqueous fluid, anethanol fluid, or combinations thereof.
 14. The process according toclaim 12, further comprising providing the second oxidant to the kerogenas a gaseous oxidant.
 15. The process according to claim 12, wherein thesecond oxidant is selected from the group consisting of peroxides, ozoneand oxygen.
 16. The process according to claim 1, further comprisingregenerating the first oxidant at a pH in a range from 6 to
 8. 17. Theprocess according to claim 16, further comprising maintaining the pH inthe range from 6 to 8 by supplying an alkaline material selected fromthe group consisting of a carbonate, a bicarbonate, an oxide and ahydroxide to the subsurface shale.
 18. The process according to claim16, further comprising maintaining the pH in the range from 6 to 8 bysupplying an acidic material selected from the group consisting of amineral acid, an organic acid, and combinations thereof to thesubsurface shale.
 19. The process according to claim 16, furthercomprising maintaining the pH in the range from 6 to 8 by supplying CO₂to the subsurface shale.
 20. The process according to claim 12 furthercomprising providing the second oxidant at a temperature in a range from0° C. to 200° C.
 21. The process according to claim 12, furthercomprising providing the second oxidant to the subsurface shale for atime of at least 4 hours.
 22. The process according to claim 1, furthercomprising mobilizing at least a portion of the organic acids at a pH inthe range from 7 to
 14. 23. The process according to claim 22, furthercomprising mobilizing at least a portion of the organic acids at a pH inthe range from 12 to 14, in the presence of alkaline material selectedfrom the group consisting of a carbonate, a bicarbonate, an oxide and ahydroxide.
 24. The process according to claim 1, wherein the mobilekerogen-based product contains C₃₅− organic acids and C₃₅+ organicacids.
 25. The process according to claim 1, wherein the mobilekerogen-based product contains in the range from 5 wt. % to 50 wt. %organic acids.
 26. The process according to claim 24, wherein at least50 wt. % of the organic acids in the mobile kerogen-based product are inthe C₃₅+ range.
 27. The process according to claim 24, wherein at least20 wt. % of the C₃₅+ organic acids in the mobile kerogen-based producthave a molecular mass number of greater than 1000 daltons.
 28. Theprocess according to claim 24, wherein at least 20 wt. % of the C₃₅−organic acids in the mobile kerogen-based product are in the C₈ to C₁₂range.
 29. The process according to claim 1, wherein at least 30 wt. %of the organic acids in the mobile kerogen-based product are diacids.30. The process according to claim 1, further comprising contacting thekerogen in the subsurface shale with a permanganate oxidant to formorganic acids and manganese oxides, including one or more of MnO₂, Mn₂⁺, or MnO₄ ²⁻.
 31. The process according to claim 30, wherein thepermanganate oxidant is selected from the group consisting of ammoniumpermanganate, NH₄MnO₄; calcium permanganate, Ca(MnO₄)₂; potassiumpermanganate, KMnO₄; and sodium permanganate, NaMnO₄.
 32. The processaccording to claim 30, further comprising providing a second oxidant,other than permanganate, to the subsurface shale, to regenerate at leasta portion of the manganese oxides to permanganate.
 33. The processaccording to claim 30, wherein the second oxidant is selected from thegroup consisting of peroxides, ozone and oxygen.
 34. A process forextracting a kerogen-based product from a subsurface shale formationcomprising subsurface shale, the process comprising the steps of: a.providing a first oxidant to kerogen in subsurface shale; b. contactingthe kerogen in the subsurface shale with the first oxidant at atemperature in the range from 0° C. and 200° C. to form organic acids;c. mobilizing at least a portion of the organic acids from thesubsurface shale to produce a mobile kerogen-based product; d.recovering the mobile kerogen-based product comprising the organicacids; and e. regenerating the first oxidant in the subsurface shale.35. A process for extracting a kerogen-based product from a subsurfaceshale formation comprising subsurface shale, the process comprising thesteps of: a. providing a first oxidant to kerogen in subsurface shale;b. contacting the kerogen in the subsurface shale with the first oxidantat a temperature in the range from 0° C. and 200° C. to form organicacids; c. mobilizing at least a portion of the organic acids from thesubsurface shale to produce a mobile kerogen-based product; d.regenerating the first oxidant in the subsurface shale; and e.recovering the mobile kerogen-based product comprising the organicacids.
 36. A process for extracting a kerogen-based product from asubsurface shale formation comprising subsurface shale, the processcomprising the steps of: a. providing a first oxidant to kerogen insubsurface shale; b. contacting the kerogen in the subsurface shale withthe first oxidant at a temperature in the range from 0° C. and 200° C.to form organic acids; c. providing a second oxidant to the kerogen inthe subsurface shale to regenerate the first oxidant; d. contacting thekerogen in the subsurface shale with the regenerated first oxidant for aperiod of at least 4 hours to form organic acids; e. repeating step (c)of providing the second oxidant to the kerogen in the subsurface shaleto regenerate the first oxidant at least once; and f. recovering amobile kerogen-based product comprising the organic acids.